SENATE RESOURCES  APRIL 14, 2026  9:01 A.M.  INITIAL VERSION DRAFT  FOR  BILLS AND PRESENTATIONS GERMANE TO 2ND SPECIAL  SESSION  MEMBERS PRESENT  Senator Cathy Giessel, Chair Senator Bill Wielechowski, Vice Chair Senator Matt Claman Senator Forrest Dunbar Senator Scott Kawasaki Senator Robert Myers Senator George Rauscher MEMBERS ABSENT  All members present COMMITTEE CALENDAR  SENATE BILL NO. 280 "An Act relating to the taxation of certain natural gas pipeline property; relating to municipal taxation limitations; establishing an alternative volumetric tax on natural gas throughput; relating to the allocation of revenue from the alternative volumetric tax; and providing for an effective date." - HEARD & HELD SENATE BILL NO. 275 "An Act relating to natural gas and natural gas projects; relating to the Alaska Gasline Development Corporation; relating to the powers and duties of the Legislative Budget and Audit Committee; relating to the value of certain oil and gas; relating to an income tax on certain natural gas-related entities; relating to the oil and gas production tax; establishing a surcharge on gas processed in the state; and providing for an effective date." - SCHEDULED BUT NOT HEARD PREVIOUS COMMITTEE ACTION  BILL: SB 280 SHORT TITLE: OIL & GAS PROPERTY TAX; MUNI TAX SPONSOR(s): RULES BY REQUEST OF THE GOVERNOR 03/20/26 (S) READ THE FIRST TIME - REFERRALS 03/20/26 (S) RES, FIN 03/23/26 (S) RES WAIVED PUBLIC HEARING NOTICE,RULE 23 03/27/26 (S) RES AT 3:30 PM BUTROVICH 205 03/27/26 (S) Heard & Held 03/27/26 (S) MINUTE(RES) 03/30/26 (S) RES AT 3:30 PM BUTROVICH 205 03/30/26 (S) Heard & Held 03/30/26 (S) MINUTE(RES) 04/13/26 (S) RES AT 3:30 PM BUTROVICH 205 04/13/26 (S) Heard & Held 04/13/26 (S) MINUTE(RES) 04/14/26 (S) RES AT 9:00 AM BUTROVICH 205 WITNESS REGISTER  DAN STICKEL, Chief Economist Department of Revenue (DOR) Juneau, Alaska POSITION STATEMENT: Delivered a presentation on SB 280. DAVID HERBERT, Commercial Analyst Tax Division Department of Revenue (DOR) Anchorage, Alaska POSITION STATEMENT: Answered questions on SB 280. MATT KISSINGER, Commercial Director Alaska Gasline Development Corporation (AGDC) Anchorage, Alaska POSITION STATEMENT: Answered questions on SB 280. RYAN FARNSWORTH, Assistant Attorney General Department of Law Anchorage, Alaska POSITION STATEMENT: Answered questions on SB 280. ACTION NARRATIVE  9:01:00 AM CHAIR GIESSEL called the Senate Resources Standing Committee meeting to order at 9:01 a.m. Present at the call to order were Senators Myers, Dunbar, Wielechowski, Kawasaki, Claman and Chair Giessel. Senator Rauscher arrived thereafter. SB 280-OIL & GAS PROPERTY TAX; MUNI TAX  9:01:46 AM CHAIR GIESSEL announced the consideration of SENATE BILL NO. 280 "An Act relating to the taxation of certain natural gas pipeline property; relating to municipal taxation limitations; establishing an alternative volumetric tax on natural gas throughput; relating to the allocation of revenue from the alternative volumetric tax; and providing for an effective date." 9:02:31 AM DAN STICKEL, Chief Economist, Department of Revenue (DOR), Juneau, Alaska, delivered a presentation on SB 280. Before I jump back into the presentation, I wanted to correct on the record two things that I did misspeak on yesterday. In relation to the municipalities that TAPS flows through, the Trans-Alaska Oil Pipeline, the three primary municipalities receiving revenue from that are the North Slope Borough, the Fairbanks North Slope Borough, and then Valdez. There are smaller TAPS-related impacts to Anchorage, Mat-Su Borough, Whittier, and Cordova. And then there was a slide where we had talked about what the state property tax would be for the gas pipeline under current law versus the proposal in the bill. I misspoke on that yesterday because I was forgot to reference a provision of the bill where under the alternative volumetric tax for a portion of the line located in a municipality, the municipality receives all of the revenue, whereas under the current property tax, there's a split between the state and municipalities. In any case, for 2035 under current law and our baseline modeling assumptions, the state would receive $239 million of property tax, and under the alternative volumetric tax, that would be $9 million for a $230 million difference. For the municipalities, it would be $497 million of current property tax, and then under the bill, it would be $63.6 million of alternative volumetric tax. 9:04:22 AM SENATOR GIESSEL I also wanted to mention something that was shared yesterday. I will add that Matt Kessinger has joined online. Yesterday it was mentioned that the initial gas supply for the pipeline in phase 1 would come from Pantheon Great Bear. I touched base with the Alaska Oil Gas Conservation Commission, they would have to approve the off-take of the gas. At this point Great Bear has not applied for any off-take authorizations. I wanted to put that out for information. 9:05:11 AM SENATOR CLAMAN For some clarity, Mr. Stickel, you just ran out a number of figures, and when I'm looking at the slides, if you could actually tell us where the figures you just read off go on the slides that we have. 9:05:27 AM MR. STICKEL The metric tax numbers to the state would be from the insurance. The current law and proposed law property tax and alternative volumetric tax numbers to the state would be from slide 30 and 32. Also relating to an earlier slide, which would be slide 18 where we lay out the alternative volumetric tax by municipality and for the state. 9:06:07 AM SENATOR CLAMAN Could you tell us which spaces to put the numbers you gave us. I don't really necessarily know immediately the figures you read off where they fit on these pieces that we're looking at. 9:06:25 AM MR. STICKEL I would be looking at slide 18, and then this shows the revenues that the state would receive from the alternative volumetric tax. Some of the questions from the committee were, if the project were to go forward under current law, what would the expected property tax value be. Looking at 2035, for North Slope Borough, the expected property tax would be $288 million. For Fairbanks North Star Borough, it would be $0.4 million. For Denali Borough, it would be $0. For Mat-Su Borough, it would be $30.5 million. For Kenai, it would be $178 million. For a total to the municipalities of $497 million, and then for the state, it would be $239 million, for a total property tax of $736 million under current law. 9:07:29 AM SENATOR CLAMAN This is all in the FY35 column. MR. STICKEL These would be annual revenue. That is correct. Under the current law with our base line capital assumptions there will be about a $736 million dollars per year property tax burden from the project and that would be reduced to about $74 million dollars under this bill. 9:08:03 AM SENATOR KAWASAKI This may be a request to help so that it would be easier to clarify if we could get something of an estimated impact graph that would state what it would be had it not changed. So, you know, just all those numbers that you read off in 2035 would be put into a graph and then, I mean, I don't know how you would estimate, but, you know, make some sort of a judgment call on how to estimate what that approximate would be so that we kind of figure out like lost revenue to municipalities. 9:08:38 AM MR. STICKEL I'm seeing that it maybe helpful to provide something similar to slide 18 under current law. We will provide that. 9:08:53 AM SENATOR CLAMAN I take it you'll be doing that not just for FY 2035 under current law, but the whole range of columns. MR. STICKEL What we'll do is provide this slide under what it looks like under current law. That would answer a lot of these questions. 9:09:27 AM MR. STICKEL moved to slide 29, Analysis Summary; Current Tax Law This slide summarized the key outputs of our modeling under current law and our baseline assumptions. This would be if the project went forward under current law. We saw what the revenues were to the various stakeholders. As a reminder, the top set of numbers here are cash flows. For the upstream and midstream, these represent gross revenues before any costs. Highlighting the break-even costs of supply numbers here, which is $4.86 in 2033 for in-state and then $9.07 for LNG exported. Those become important numbers as we compare to different scenarios and different market conditions. 9:10:38 AM CHAIR GIESSEL For clarification, gas commodity charge, is that the price at the wellhead. MR. STICKEL Yes. 9:10:53 AM MR. STICKEL moved to slide 30, State Revenues by Year; Current Law. Slide 30 shows a chart of annual state revenues under the current law analysis. This would be if the project went forward under current law without property tax relief. We're looking at a little over $200 million per year of property tax, around $600 million per year if you include royalties and corporate tax, and then about a billion dollars per year total. These are revenues just to the state once we add in the production tax impacts. 9:11:30 AM CHAIR GIESSEL At year 2033, that peak, and then it plateaus, this must be after the export facility is fully functional. MR. STICKEL That is correct. 9:11:51 AM SENATOR DUNBAR Could you explain the TBTU per year 1150. How does that compare to the 3.5 billion is usually the number we see for when the LNG is fully being exported. This is a different measurement. How is that, are you assuming that same amount being exported. 9:12:19 AM MR. STICKEL The left axis is the revenues, and then the right axis is the volumes. This one's been labeled in trillions of BTUs per year, which a BTU and a thousand cubic feet have a rough equivalency, but that top threshold is equivalent to the 3.5 billion cubic feet per day of full capacity of the project. 9:13:00 AM MR. STICKEL moved to slide 31, Analysis Summary; Proposed Legislation. Slide 31 summarizes some of the key outputs of the modeling under the proposed legislation and with the baseline assumptions. Everything the same as slide 29, except we implement SB 280 and the alternative volumetric tax. Under this analysis through 2062, there's $22.5 billion of state revenues, which is $7.2 billion less than current law. There's $4 billion of municipal revenues, which is $13.3 billion less. There's $60 billion to the upstream producers, that is the same as the prior analysis. And then there's $68.5 billion to the midstream in revenue, which is $1.5 billion less than under current law. Why is that less is because the project, the cost to operate the project is less with the lower property tax burden, and we are assuming a 10 percent return to the midstream owner. They're making a 10 percent return on a lower base when we provide the property tax relief. In terms of cost of supply, under our baseline, we get a $4.43 break-even price for the in-state cost of supply, which is 43 cents per thousand cubic feet reduction to in-state, and then $8.48 per thousand cubic feet, which is a 59-cent per thousand cubic feet reduction to the price that would allow the project to break even in the market for delivered LNG. 9:14:52 AM SENATOR MYERS I'm looking at your cost of supply summaries. The in-state versus the LNG, the gas commodity charge, gas treatment plant toll, and pipeline toll are slightly higher on the LNG portion. Why is that. 9:15:12 AM MR. STICKEL The gas commodity charge for LNG includes some additional treatment costs. 9:15:28 AM SENATOR MYERS We just clarified that's at the wellhead and so treatment would come later, but then you've got your gas treatment plant toll, and that's, if all the gas is run through the same treatment plant, it should be the same. The producers don't care if it's getting sold in Anchorage or if it's getting sold in Japan. They're going to charge the same price. The gas treatment plant, it's the same plant. It's all going to get charged the same. It's the same pipeline. That's all going to get charged the same. The LNG plant and the ship and the overseas shipping, of course, that's different, but we're talking about the same gas running through the same infrastructure, so why is it different. 9:16:06 AM MR. STICKEL I was hoping I had Mr. Herbert, my commercial analyst on the line. I'll follow up with that. I know we have an answer and he could answer it off the top of his head, but I'll get that for you guys. 9:16:31 AM CHAIR GIESSEL You've pointed out the change in revenue for each of these. How much will this save the consumer and have you calculated down to that level. 9:16:46 AM MR. STICKEL We've done some initial analysis looking at after contracts expire for ENSTAR in particular in 2033, what are the options that exist there and how does the AKLG project compare to imported gas being the primary concerns there. We looked at a 2023 study by BRG that was done for ENSTAR, and that had a cost of imported gas. We inflated that price up to 2033 dollars and it came out to about $17 per thousand cubic feet for imported gas into the market. Our baseline here for in-state gas would be $4.43 per thousand cubic feet. That would be a savings of about $12.50 per thousand cubic feet. Looking at ENSTAR customers as a total, which consume about 34 billion cubic feet per year, that would be about a $358 million annual savings or about $10.7 billion over a 30-year time horizon. We looked at ENSTAR in particular because they have some readily available information around number of customers and exactly what their prices are. If we extrapolated that from the 34 billion cubic feet that ENSTAR is using to a larger number, such as the 65 to 70 billion cubic feet that are consumed in the inlet or potentially a larger number if there's, you know, incentive, if new demand is incentivized, things like if there is a Fairbanks spur line, some sort of an industrial base load consumer could be data center, agrium, sales to mines, then the savings could be significantly higher than those ENSTAR-only numbers. 9:19:09 AM SENATOR WIELECHOWSKI On that question of the savings to consumers, it's 43 cents per MCF is what the savings is for the property tax cuts, correct. 9:19:28 AM MR. STICKEL 43 cents per thousand cubic feet is the comparison of the delivered price to utilities under, if you assume the project goes forward under current law versus under this bill. 9:19:50 AM SENATOR WIELECHOWSKI To do a comparison on how much the people of Alaska would be giving up, the state property taxes are reduced by $230 million, which divide that by 600,000 Alaskans comes out to $383 per person. The muni cut is $434 million, which is probably $700, $800 per person, but the munis are separate. I guess the point that is curious to me is that the amount of, I checked with ENSTAR, the amount of natural gas that the average Anchorage residential customer uses is 139 MCF per year. When you multiply that by 43 cents, you get $58.38, which means that the average household in Anchorage with that 43-cent savings is saving $58.38, but they're giving up $239 million in state property taxes, which is the equivalent of $383 per person. A household of four is giving up almost $1,500 to get its potential PFDs or potential state services in exchange for $58.38 of savings. Does that sound about right. 9:21:26 AM MR. STICKEL 9:21:56 AM SENATOR WIELECHOWSKI 9:22:28 AM SENATOR MYERS The question is what is the alternative. If your view is that this project will not go forward under current law, then the comparison would be, what is the alternative source of gas, you know, by imports, which is what I quoted. If your view is that this project will go forward under current law, then the numbers you cited would be more accurate. 9:23:00 AM SENATOR MYERS I was looking at the cost of supply charts that Mr. Stickle had on both slides 29 and 31. I believe they're the same on these three pieces. The LNG break-even price versus the in-state break-even price, the gas commodity charge, the gas treatment plant toll, and the pipeline toll are all slightly higher for the LNG price. And I'm just curious as to why, since it's the same gas and the same infrastructure. 9:23:42 AM DAVID HERBERT, Commercial Analyst, Tax Division, Department of Revenue (DOR), Anchorage, Alaska, answered questions on SB 280. Something we try and highlight in these is that these cost of supply are based off of the price to the end consumer, be it the utilities or LNG customers. And as a result, the total cents here are based off of the output volumes. For the LNG, there's additional fuel that needs to be transported down the gas line process in order to run the liquefaction plant, and that adds the cost there across the board. 9:24:33 AM SENATOR MYERS To clarify, so effectively what I'm hearing is because of the extra volume needed, I'm assuming that means we're going to need to run pipelines out to Point Thomson or a couple of the other North Star Endicott to get the gas. You're factoring that, the cost of that extra infrastructure being built into those extra costs going up a little bit. 9:25:02 AM MR. HERBERT In this case, those costs are already baked into both of these things, but in order to run the liquefaction plant itself, a certain amount of additional gas needs to be transported just for that. Instead of letting the cost associated with that gas get incorporated into both sides of it, they're only shown on the LNG, so the in-state customers aren't subsidizing that. 9:25:37 AM SENATOR MYERS It's the cost of the LNG. It's the extra gas that is necessary in order to run the LNG plant and that's just back added into the other pieces. 9:26:00 AM MR. STICKEL moved to slide 32, State Revenues by Year; Proposed Legislation. Slide 32 is our same annual revenue chart under the proposed analysis. Looks very similar to the current law slide, except it's about $230 million per year lower across the board due to removing that property tax and replacing it with the alternative volumetric tax. State revenue from the AKLNG project with this bill passed is looking at about $800 million per year total. 9:26:37 AM SENATOR DUNBAR Two things. First, just to reiterate what I said yesterday, one of my primary goals in this bill, if I'm going to support it, is to prevent that happening in 2028 through 2032 where our revenues go negative. If we're going to produce that much revenue in the future, there's no reason to have any period where we can't put those costs out into the future. So that's one. The second is, I think if you were a layperson looking at this graph, it looks like the total government revenue here, approaches is quite close to the line in the previous graph on 30. It's actually over the line at the time. You might interpret that as saying the government is taking the vast majority of the revenues, if that is indeed the revenues. If you look at the prior slide and you've got the upstream owners and the midstream owners and all of them together, that adds up to 177.5 billion approximately. About 72.5 percent of it is taken by the owners and 28.5 percent is taken by the government. The government, less than 30 percent of the total revenue is captured by the government, which is probably fair. The vast majority of the revenue goes to the producers and the midstream owners. I guess one of my questions is, why doesn't this graph reflect that. Why isn't the gap between the lines and the revenue equal to 70 percent of the revenues produced. Does that make sense. If you look at the prior slide, 72.5 percent of all revenue related to this project is captured by the upstream owners and the midstream owners. Good. But this graph makes it look like it's a much tighter gap between the revenues produced and the state and all government revenue. What am I missing there. 9:28:53 AM MR. STICKEL This chart shows two things. This shows total gas sales on the right axis and the dotted line, and then total state revenues only in the stacked bar charts. This chart is only looking at that state revenue number and how that breaks out into the different components. We could certainly prepare a chart that shows all the revenues to the different entities, and that would demonstrate that the revenue to the state is a fraction of the total revenue generated by the project. 9:29:33 AM SENATOR DUNBAR I don't understand what the dotted line was. I thought the dotted line was trying to illustrate the total revenue generated by the project. Why does the dotted line exist if that's not what it's showing. 9:29:46 AM MR. STICKEL What the dotted line represents is gas sales from the project. The reason we included that is we wanted to show the start of the project where there are no gas sales. We wanted to show what the impact on state revenue is for the first couple of years when there's only in-state gas sales. Then we wanted to show the ramp up period where the full export project is coming online. Then to show that the significant state revenues really do start in 2033 when the project is fully operational. 9:30:23 AM SENATOR DUNBAR I don't think this is intentional by the Department of Revenue, but that is a wildly misleading graph because people look at it and they associate the dotted line with the revenue on the y- axis on the left. What you're saying is, no, the dotted line only applies to on the right. You see what I mean. Why not just make a dotted line that tracks with the revenues, which would also track with the gas sales, but they'd show a vastly different. They would show this line would go way three times off the graph to show all the profits being made, or all the revenue being generated, perhaps not profits. Does that make sense. 9:31:10 AM MR. STICKEL I understand the alternative slide that you're discussing. We'd be happy to provide a version of that. SENATOR DUNBAR Please don't put this slide into the public like this, because again, I think unless there's some way to be very clear, because it even says LNG and gas sales, which implies that there's some dollar figure on the bottom there with the dotted line. A person's going to look at this and say, man, the government is taking the vast majority of the revenue being generated here. If they look at the thing on slide 30, they'll come to the conclusion that the government revenue exceeds the total revenue for a portion. No wonder they need this giant tax break. That's not at all what this is showing. I don't think it was intentional. I hope we can change this before it goes out for broader public consumption, Madam Chair. 9:32:05 AM MR. STICKEL Absolutely not intentional. I see that we can improve our labeling on this slide if we're going to include that dotted line, and we'll take a look at that. 9:32:18 AM SENATOR MYERS On 29 and 31, when we had the dollar figures for the upstream motors and the midstream motors, I believe you said that that was not profit, that was strictly cash flow. If we, once we subtract it out the upstream and midstream costs, then those, the actual profit would be significantly smaller than that. Is that accurate. 9:32:44 AM MR. STICKEL That's accurate. 9:32:54 AM SENATOR CLAMAN Let's start at slide 32. Under this proposal, we often talk about how the gas line is going to bring enormous revenue to the state, and particularly at least when we sit in the legislature, we think, is this going to be a big increase in revenue to state government. I'm looking at slide 32. Never in a single year do the revenues to the state exceed a billion dollars. I'm not minimizing that a billion dollars is no small amount of money to the state, but I think about how much we're drawing annually on the POMV draw from the earnings reserve to fund state government, which is over $3 billion and has been for the last few years. I look at this, which shows less than a billion dollars coming to the state in the best years. If this project has potential revenue to the state, is there some other means the state can achieve great revenue from this particular project because it doesn't look like it's coming from royalties and production taxes. Not to understate that we don't need the revenue, but this doesn't look like a game changer. Where is the big revenue to the state in the project. 9:34:23 AM MR. STICKEL I would suggest that $800 million dollars a year is a significant increase to state revenue. SENATOR CLAMAN I agree it's a significant increase but it doesn't really change the picture dramatically because $800 million is about 25 percent of the POMV draw from the earnings reserve. 9:34:47 AM MR. STICKEL I was going to add, gas is a lower value commodity than oil. That is a truth. And so when you're looking at a gas, there is a lesser amount of profit overall with gas than oil, and that's something to keep in mind. 9:34:54 AM SENATOR RAUSCHER joined the meeting. 9:35:08 AM CHAIR GIESSEL That's a really important point that we often forget, because we are used to dealing with oil. I'll just interject that. But the other point you make, Senator Claman, because you're referring to the percent of market value that is available for general fund use, and we are proposing actually reducing the percent of market value percent from 5 percent down to 4.5 percent progressively over a five-year period, which if you apply that to this graph, it will hit at about 2032, 2033. I don't have the bill in front of me that's being considered, but we need to take that into consideration also, though this is not our only source of revenue. 9:35:55 AM SENATOR CLAMAN The question I'm raising is, if there is this potentially more significant win for the state than just what's on these graphs, where is that. Is that somehow that we have ownership interest or greater ownership interest in pieces of the pipeline that will bring us revenue separate from royalties and production taxes. 9:36:23 AM MR. STICKEL That's certainly an option that the legislature could consider to have an ownership interest, you know, broader economic impacts, economic development in the state. And then what we haven't really looked at is the impact on exploration and development above and beyond what's in the revenue forecast. I spoke to that a little bit yesterday in some of the slides, but this idea that when you have a sales mechanism for gas, that it makes exploration and development more attractive generally on the slope. 9:37:11 AM SENATOR WIELECHOWSKI Do you have any idea what the costs are to the upstream owners to produce $1.50 worth of gas are. Right now, my understanding is they're injecting like 8 billion cubic feet a day, they're just reinjecting it. I would imagine the costs to the producers are pennies, extremely low. Does that sound, is that probably about right. 9:37:38 AM MR. STICKEL We do have assumptions around what the incremental cost of the gas and associated new oil will be. Those are baked into the model. I don't have those at my fingertips, but we do have assumptions that we've developed with AGDC. 9:37:55 AM SENATOR WIELECHOWSKI Profits for industry, I guess. If you have a $1.50 gas, which is what you're estimating, the state's share is $1.50 times, we get a 12.5 percent royalty, we get a 13 percent gross tax, that's 25.5 percent. That comes out to $38.25. Corporate income tax is a little bit, not as much as it could be, but the property taxes are very little. It's maybe $0.40, I'm guessing. The producers, on the other hand, are getting it costs virtually nothing for them. They're just producing it and reinjecting it right now. They're probably making a dollar in MCF. Does that sound about right. 9:38:56 AM MR. STICKEL I would have to look at our assumptions to validate that exact number. 9:39:04 AM SENATOR WIELECHOWSKI Can you provide us with that data. MR. STICKEL Yes. We'd be happy to do that. As I mentioned we do have assumptions baked into the modeling for incremental cost at Prudhoe Bay and Point Thomson. 9:39:22 AM CHAIR GIESSEL The other thing to consider here is what I shared at the outset. The idea that Pantheon is going to be the initial source of gas is a questionable assumption, since they haven't applied for gas off-take yet. Not thinking that there doesn't have to be gas treatment costs at the very beginning is a flawed assumption, in my opinion. 9:39:57 AM SENATOR RAUSCHER This regards to the question by Senator Wielechowski. When they reinject air, they have different reasons for it to bring up more oil. In regards to the question by Senator Wielekowski. When they re- inject and inject, they have different reasons for it, to bring up more oil. Sometimes they have too much gas that comes up because of the oil that they're taking out of the ground. This is not a complete search for gas. This is something that happened along the way, which may be too much for them to re- inject just to bring up new oil or whatever, but when you're looking at actually providing the gas that we're providing here and liquefying and getting it in the pipeline, I think that the costs go up considerably other than why they're re-injecting what you're talking about there and the cost that it seems like would be almost nil. These are two different types of gas supplies that we're trying to come up with and volume that we're needing. That's just my opinion from working up there. 9:40:59 AM SENATOR MYERS To go back to Senator Claman's question about the benefit to the state. We're talking about dollar benefit in terms of direct royalties and taxes, but I mean, the other benefit to the state would be lower energy costs for residents, hopefully fewer people leave the state because it gets more affordable to live here. Maybe some businesses become more profitable. We start some businesses. You mentioned Agrium potentially restarting up if they've got a decent, a reliable supply again. Something gets thrown on the property tax rolls with Kenai. If other businesses can get started, those increase the property tax rolls locally for a lot of places. At Department of Revenue, do you have any modeling that can estimate those types of benefits, even though they aren't necessarily direct benefits to the state treasury because, we don't have a broad-based tax. Can you model some of those other benefits to municipalities or to the population in general. 9:42:00 AM MR. STICKEL That's something we've been looking at, how we can model those broader economic benefits. I'm not sure that's quite ready for prime time, but qualitatively, we can certainly speak to some of what we're looking at. It's things like light data centers, like a restart of an Agrium plant, like a line out to support mining operations like the Donlin mine, like the Fairbanks spur line. And certainly those have economic impacts that go beyond just the direct revenues. 9:42:40 AM CHAIR GIESSEL I appreciate what you spoke about in terms of opening and restarting businesses and that resulting, of course, in property tax and so forth. Remember under 4356-022, all municipal property taxes, ad valorem sales tax, municipal gross and net income, license fees, excise, municipal charges, et cetera, related to consumption, whatever, are all prohibited during construction, which is the most impactful time. You see the line there, it actually, the line starts way over in 2022. We're actually in 2026 already. But those, that prohibition on any municipal taxes of any kind continues until they reach a billion cubic feet, which this optimistically is projecting in 2033. That's a pretty optimistic projection. It could be a while before that idea of additional municipal income would come to fruition. Just some practical considerations. 9:43:54 AM SENATOR MYERS I understand that we may need to clarify that because I think that the point of the bill here is to say we don't want to tax them while they're in the middle of construction, but again, there will be some spillover effects, and we do want the municipalities and the like to be able to capture those. I'm all in favor of clarifying that. To say, I don't think it's quite accurate to say, because that's what the language is in the bill right now, that for example, the Kenai, I wouldn't be able to tax the Agrium plant just because they're using the gas because that doesn't have anything to do with the construction. I understand we may need to clarify that, but just thinking about where the benefits go. 9:44:39 AM SENATOR WIELECHOWSKI On the pipeline, can you go back a slide to 31. OK, so I'm struck by the number, the disparity in cumulative to 2062. You got $22 billion to the state, $22 billion to the feds, $3 billion to the uni, $60 billion to upstream, $68 billion to midstream. And I'm trying to figure out what's the share is. We talk about a third, a third for the state, feds, upstream. In this case, we got midstream. What profit do you estimate the midstream owners are getting from that $68 billion. 9:45:24 AM MR. STICKEL Our model assumes a 10 percent rate of return for midstream. 9:45:34 AM SENATOR WIELECHOWSKI That would be $6.8 billion dollars. 9:45:40 AM MR. STICKEL Roughly. 9:45:46 AM SENATOR WIELECHOWSKI On the upstream do you have any sense on what kind of profit they are looking at. MR. STICKEL I don't have that number at the top of my head. 9:46:02 AM SENATOR WIELECHOWSKI I'm curious about those federal numbers. Why is there a negative federal number from [2042]. MR. STICKEL The federal revenues represent two things, one is a federal corporate income tax which would be we would assume a slight offset to federal corporate income taxes during the build out phase, when there is money being laid out. Also, we're assuming enefits from the 45 Q credits, which are credits for carbon capture which apply to the gas treatment plant. Those are the The federal revenues represent two things. One is a federal corporate income tax, which would be, we would assume, a slight offset to federal corporate income taxes during the build-out phase when there's money being laid out. Also, we're assuming benefits from the 45Q credits, which are credits for carbon capture which would apply to the gas treatment plant. Those are a positive benefit to the project, but an outlay from the federal government during the initial years of the project. 9:46:54 AM SENATOR WIELECHOWSKI So those 45Q credits, I assume, those go to the upstream owners or the midstream owners. What's your expectation on that and are you reflecting the shift to those owners in this slide. MR. STICKEL We assume that those 45Q credits are realized by the midstream owner at the gas treatment plant, and that is baked into our modeling, yes. 9:47:25 AM SENATOR WIELECHOWSKI Explain how you're valuing that. That's, so you've got a ton of carbon, maybe explain more, and explain how that's reflected in here, and how many tons you're estimating. 9:47:47 AM MR. STICKEL I'll see what I have at my fingertips. I may have to defer this one to my lifeline. 9:48:09 AM MR. HERBERT We right now are estimating 7.5 million tons of CO2 removed at the GTP plant per year once everything is at full operations and that is sequestered earning a credit per ton of, according to the current 45Q law, which is $85 per ton today, but increases with inflation over time. So by the time the project is running at full capacity, we're talking about $100 per ton of CO2 sequestered, which combining those two numbers together for the first 12 years of the project, which is the length of those 45Q credits we're talking about, approximately $750 to $900 million over that time frame as credits that are either cashable or immediately transferable from the federal government to the project. 9:50:03 AM SENATOR WIELECHOWSKI where are you anticipating that the carbon will be stored. Is there a well that's been approved. I know we had approved giving the department that authority to go forward on getting EPA authority to start this process. Have you done that and where are we at in that process. 9:50:28 AM MR. STICKEL That would be a good question for Matt Kissinger with the AGDC. 9:50:43 AM MATT KISSINGER, Commercial Director, Alaska Gasline Development Corporation (AGDC), Anchorage, Alaska, answered questions on SB 280. There are two ways to sequester your CO2 under the 45Q credits. There is the permanent geological sequestration, and then there's use for EOR. As this project has developed, the base case assumption has always been that the CO2 would be returned to Prudhoe Bay. In fact, it's a distal part of the reservoir, which is the target area for it to go into. By putting it into Prudhoe Bay, you're just by default taking the EOR credits rather than the permanent geological storage credits. The enhanced oil recovery mechanism is the pressure itself from putting those molecules back into the reservoir, and then, you know, there's also the potential that the CO2 would be so miscible and be able to withdraw more oil just to do it even in the reservoir. 9:51:48 AM SENATOR DUNBAR If we go forward one slide, and you must have mentioned this, but I must have missed it. What's going on in 2038 here again. There are two different shades of blue here, I think that's the property tax and ABT, but it might be the production tax. It just disappears for a year and then it comes back. Could you explain that again. 9:52:10 AM MR. STICKEL We are assuming that for Point Thomson in particular, that there's two major capital outlays associated with expanding that field, one that occurs prior to full exports and another in 2038. That represents an expected reduction to production tax in that one year when we're expecting a major outlay of funds at Point Thomson. 9:52:39 AM SENATOR DUNBAR Just remind me, that production tax is for both oil and gas, or just production taxes on the gas. 9:52:47 AM MR. STICKEL This is total production tax. The production tax due to the state is paid on a statewide basis, so we combine the oil and the gas from the producers. 9:53:04 AM SENATOR DUNBAR If this all goes forward, I think the legislature in 2036 is going to have a pretty detailed discussion about that. 9:53:15 AM MR. STICKEL These are incremental production tax revenues above and beyond our spring revenue forecast. And so in 2038, we would still be expecting additional revenue above and beyond the existing forecast, just not hundreds of millions of dollars like we are in other years. 9:53:36 AM SENATOR CLAMAN Senator Wielechowski was asking some questions about, actually took a question from Mr. Kissinger asking about the CO2 stuff, but I think he also asked the status of an EPA application to get permitted, and I'd never heard an answer to that. 9:54:03 AM MR. KISSINGER The Class 6 wells, as I mentioned, there are two ways you can earn the credit through the permanent geological storage or through the VLR. If the Class 6 wells are needed for the permanent geological storage. These were, this gas is used as ULR and the reservoir would just be sent through the approved system into either existing injector wells or new injector wells. Those wells would not need to be Class 6 wells as far as I understand. It would be more than a year. 9:54:43 AM CHAIR GIESSEL My understanding is AOCC has achieved authorization for Class 6 well, but let me confirm that. It's been a couple of months since I last spoke to them, and I do have another inquiry out to them related to Great Bear. So I'll ask that question in the next day or so. 9:55:03 AM SENATOR WIELECHOWSKI Going back to Senator Dunbar's question on lease expenditures. Can you get us a chart that had the lease expenditures, could you get us a chart that had the amount of lease expenditure, the cost of lease expenditure deductions to the state per year from this project. 9:55:18 AM MR. STICKEL I will provide our assumptions around incremental lease expenditures associated with the project. 9:55:30 AM SENATOR WIELECHOWSKI Yes, the lease expenditures, but also the loss in revenue to the state from those lease expenditures. MR. STICKEL We will include the increase or decrease in revenue associated with these expenditures. 9:55:57 AM MR. STICKEL moved to slide 33, Sensitivity Matrix; In-State Gas Break-Even Price, Nominal $/Mcf in 2033 This gets at some of the questions around uncertainties of assumptions around the AK LNG project. Two of the biggest assumptions that we've identified have uncertainty around them are what the gas price will be that the producers receive and how much the project will actually cost. There was some discussion yesterday of potentially some different numbers running around. Within Department of Revenue, we don't have final or confidential numbers on those two items, we prepare some extensive sensitivity analysis. We show on the top, what we're showing here is the break-even price for the cost of supply that we've shown on previous slides. On this chart, we're showing that in-state cost of supply, and we are varying the gas purchase price on the x-axis, which is how much do the producers receive for selling the gas into the project. Then we are varying the capital cost for the project. We start with our $46 billion capital cost assumption as our base capex, and we run increments of that up to a 100 percent cost overrun. You can look at what is the impact if there is a capital expenditure that's 20 or 40 percent higher than the baseline costs. Our baseline assumptions are the $1.50 per thousand cubic feet for the purchase price, and then the $46 billion project cost. In the baseline, this bill would reduce that in-state break-even price from $4.86 per thousand cubic feet down to $4.43 per thousand cubic feet. But then you can see the significant range of outcomes that are potential there and the risk to the developer for the higher capital cost in particular. 9:58:12 AM SENATOR DUNBAR Just so we can put this in context, this break-even price, what is the sort of, what is the international price that they'd be competing with right now. 9:58:27 AM MR. STICKEL This looks at the in-state price. This would be the price to in- state utilities. I do have another, the next chart actually looks at the international LNG prices. SENATOR DUNBAR The second one says Alaska LNG, but its still in-state even though the in-state users are not using the LNG. MR. STICKEL Right, we are showing the capital cost for the entire project and then what is the delivered gas to in-state utilities. SENATOR DUNBAR Right, because it's all one project. MR. STICKEL The next slide will show a similar chart looking at LNG sales into global market. 9:59:18 AM CHAIR GIESSEL One of the concerns that we have is the phase one and it existing as an isolated occurrence. For the first few years, I think on your previous slide, 32 and 30, the first few years when it's in-state only, there's quite a loss. What is the price of, what is the break-even price there. What are Alaskans going to look at paying. 9:59:50 AM MR. STICKEL I have some numbers based on a fall 2025 version of the analysis. We haven't fully completed the most updated spring version of the analysis, but the numbers should be fairly comparable. If the project were to build the pipeline phase one only and not proceed to the full project, we estimated a break- even gas delivered to utilities price of about $12.52 per thousand cubic feet. 10:00:26 AM SENATOR WIELECHOWSKI Just so I understand this, so the base, looking at the top one here, the base CapEx at $1.5446, that, is that the delivered price to the consumer in South Central, or are you assuming other charges on top of that. MR. STICKEL The prices here represent the delivered price to utilities. This would be the cost that a utility such as NSTAR would be purchasing the gas for, and then the consumers would be paying a higher price that would represent the transportation cost that NSTAR has. 10:01:14 AM SENATOR WIELECHOWSKI Do you have a rough estimate of what that number would reflect from 486 to 586, 686. MR. STICKEL Not off the top of my head. 10:01:33 AM SENATOR WIELECHOWSKI If you could get that. I'm just curious, are you assuming that cost overruns are going to be passed on to the consumers. Is that what this assumption is making. MR. STICKEL Yes. The way this looks is we assume that the midstream operator will earn a 10 percent rate of return, and then we look at what is the price that would be required to allow them that 10 percent rate of return on different levels of capital costs. That's how we've done the modeling approach. What would happen in reality is the midstream operator would have a price that they would pay to the upstream, they would have a price that they would sell the gas for, they would have a cost of the project, and they would bear a lot of that risk at the midstream. 10:02:42 AM SENATOR WIELECHOWSKI That was my understanding of the testimony, was that the cost overruns would not be passed to the consumers. I'm not sure what to make with this chart. Are you saying that if there's a 20 percent cost overrun, it won't be 543 if it's $1.50 gas. It'll be something different. MR. STICKEL What we're showing here is, given if you assume a 20 percent cost overrun, for instance, and if you assume the $1.50 purchase price, for instance, then a $5.43 per thousand cubic feet would be required. That would be the price that the midstream operator would have to sell the gas for to get that 10 percent return. Now, they could sell it for a lower price and get less than a 10 percent return. Then under the bill before you, that break-even in that scenario would go from $5.43 down to $4.92. It would make a lower required price for them to earn that rate of return. 10:03:52 AM SENATOR WIELECHOWSKI To be clear, you heard the same testimony I did, that cost overruns will not be passed onto consumers, correct. MR. STICKEL Correct. 10:04:05 AM SENATOR DUNBAR What volume of consumption are you assuming here from in-state. MR. STICKEL I need to defer the question. Mr. Herbert has the answer at his fingertips. 10:04:33 AM MR. HERBERT I have a revenue in the version of the model you have that's being presented in front of you, we have an in-state sales demand of approximately 67 BCF per year, but growing over time. 10:05:12 AM SENATOR DUNBAR 67 BCF per year, you're not saying the whole project could survive selling 67 BCF per year at this price, right. This chart cannot exist without the chart on the following slide where they are selling the full 3.5 BCF per day. Is that correct. 10:05:37 AM MR. STICKEL Yes, that's correct. So these represent the in-state delivered sales assuming the full project goes forward. Then again, if we assume, if the full project didn't go forward and it was just the phase one, yes, the in-state prices would be significantly higher. 10:05:59 AM SENATOR DUNBAR My follow-up question will be on the next slide. The point is sort of, this is an interesting slide because this slide cannot exist, and none of this will happen unless what happens on the next slide goes forward, which is they are competitively selling a much, much larger volume of gas into the international market. That's my question about what price are they competing with goes to the next slide, but it's tied to this slide in the sense that if they can't compete on the next slide, this slide doesn't exist. This doesn't happen. 10:06:39 AM SENATOR RAUSCHER Assuming these sellers wanted to maintain their projected 10 percent profit, the consumers will bear the cost of cost overruns, is what I just heard, right. What I'm trying to get through before I get the answer is, who is the consumer. The consumer could be whoever's purchasing overseas, as opposed to a different price which we could get in-state. Is that a possibility. I'm trying to understand the actual definition of the consumer and who's actually going to absorb the cost. 10:07:31 AM MR. STICKEL No, we are not assuming that cost overruns would be borne by the consumer. We've developed the model, it's based on a, the initial model was based on a tolling model for a regulated pipeline where there is a regulated return. We've basically modified this approach to modeling to the current project. What we're presenting here is, if you assume a given sales price and a given construction cost, and if you assume a 10 percent rate of return, then what is the sales price to utilities that would be required for the project to earn that 10 percent rate of return. This would be, these in effect would be break-even prices for Glenfarne. What would they need to sell the gas for to achieve their 10 percent rate of return. As far as who is the consumer, when we do the modeling, we're looking at sales to utilities. So for in-state sales, it would be sales to, it would be sales to Instar, to Golden Valley, other utilities like that. For LNG, it would be sales to the utilities, you know, potentially overseas. 10:09:01 AM SENATOR RAUSCHER The bulk of the gas is going overseas. MR. STICKEL That is correct. SENATOR RAUSCHER They are basically going to accept the bulk of the extra cost. MR. STICKEL The LNG market is a global market, and so the prices for the delivered LNG will be based on market prices. Glynnfarne would go out and negotiate those contracts based on what the market will bear for delivered costs. They will negotiate the upstream prices with the producers, and they will outlay the funds to build the project. They will ultimately bear the risk of a cost override unless they have a very unique contract arrangement where they could do some sort of cost sharing. 10:10:03 AM CHAIR GIESSEL I just wanted to clarify. I had asked you the question, what if just the pipe were built, only the pipeline, and you said the break-even for that would be $12.52. I wanted to clarify, is that the price that ENSTAR would pay if only the pipe were in the ground. MR. STICKEL To put a finer point on that, and these were based on the fall version of the model, so they're not exactly directly comparable to what you're seeing here, but the break-even price for in- state with phase one only would be $12.52 per thousand cubic feet under current law if the project went forward, and it would be $10.72 per thousand cubic feet under the proposed law. 10:10:58 AM CHAIR GIESSEL To clarify that's the price to ENSTAR not the price to the consumer. MR. STICKEL That is correct. 10:11:08 AM SENATOR CLAMAN So there's several questions about that the consumer, meaning the gas user in ENSTAR, the homeowner in NSAR's example, isn't going to pay the cost overruns. Who is going to pay the cost overruns. Does that just mean in the 10 percent rate of return that you've calculated that they have to absorb those cost overruns in the 10 percent and reduce their margin, or does it get paid somewhere else. MR. STICKEL yes, the assumption is the midstream operator would have to absorb cost over runs. 10:11:53 AM SENATOR WIELECHOWSKI Has Glenfarne agreed to not seek a higher than 10 percent rate of return. MR. STICKEL The 10 percent rate of return, this would not be a regulated pipeline. The 10 percent rate of return is a modeling assumption that we've developed. They could certainly get a higher than 10 percent rate of return. They could very well get a lower than 10 percent rate of return. 10:12:18 AM SENATOR WIELECHOWSKI Who would decide what their rate of return is. MR. STICKEL Given that its not a regulated pipeline, the rate of return would be a function of the purchase price for the gas, the expenses to build and operate the pipeline, and then the selling price for the gas. 10:12:39 AM SENATOR WIELECHOWSKI Is it the department's position that the RCA or FERC doesn't regulate this pipeline. MR. STICKEL My understanding is that this would not be a regulated pipeline. I'm happy to call on a lifeline for more details on that. 10:13:11 AM MR. KISSINGER This project is a FERC regulated project. It's regulated under Section 3 of the Natural Gas Act, and it is not subject to RCA regulation. It is under the exclusive jurisdiction of the federal government. 10:13:36 AM SENATOR WIELECHOWSKI My understanding is FERC doesn't regulate returns, so it would be up to the, the pipeline producer or the pipeline builder to decide what their rate of return is. 10:13:51 AM MR. KISSINGER As you know, the market will determine what returns are required to attract the investors. What we've done in coordination with the Department of Revenue is take a stab at an assumption on what would be attractive to the market. The market is also going to factor in their cost overrun risk exposure. So, yes, the midstream will take on the cost overrun risk, but when the project is fully contracted, meaning all the upstream contracts, as Mr. Stickle mentioned, all the downstream contracts, L place, and EPC contracts constructed, there needs to be sufficient room to bear what is the perceived cost overrun risk by the investors. We're trying to see if there's sufficient room for that. 10:14:52 AM SENATOR WIELECHOWSKI We've heard throughout the presentation that the expected rate of return will be 10 percent, is that what you expect it to be. MR. KISSINGER We've always assumed here at AGDC a 12 percent pre-tax rate of return and a 10 percent after-tax rate of return. But again, as we seek the investors at FID, that's when the market will make itself known. Those are somewhat standard infrastructure level rates of return for projects that are project-financed with highly creditworthy counterparties. 10:15:41 AM SENATOR CLAMAN Let's go back to the consumer and the cost overruns wouldn't be borne by the consumer in an unregulated pipeline. Where does the consumer go to get assurance that, in fact, those costs have not been put onto their utility bill. 10:16:34 AM CHAIR GIESSEL The Regulatory Commission of Alaska (RCA) regulates ENSTAR and the price it charges consumers. 10:16:45 AM MR. KISSINGER It is our understanding that the RCA regulates the gas sales agreements to these utilities, so the utility would take the application to the RCA in much the same way they do now. They pick the application for North or Cook Inlet gas sales to the RCA. The RCA doesn't go and examine all the costs involved and then make a determination on whether the gas sale itself is fair and reasonable, is my understanding. 10:17:19 AM SENATOR CLAMAN If you've got an unregulated pipeline that's coming in, the RCA really isn't in a position to say, well, they're charging too much for the gas that's coming in the pipeline and potentially putting in the costs that are very much showing up now in the consumer's bill. RCA would say, well, where's the point at which we can say, no, this is not OK, because they actually don't regulate the pipeline that's getting it there. I have questions about the certainty, the proposal that we wouldn't charge it to the consumer is just another day when somebody said, well, these were cost overruns, it's built into the pipeline gas price that's coming to ENSTAR. ENSTAR says this is the best price we could get and it's got those very prices getting shared to the consumer. 10:18:08 AM CHAIR GIESSEL It is my understanding, and I will confirm that, that if this were an in-state pipeline only, that the Regulatory Commission of Alaska would regulate it. However, the Glenfarne entity has gone to FERC and permitted this as a single project, which includes an export facility, which FERC does have jurisdiction over. My understanding is that the Regulatory Commission of Alaska will regulate what the rate of return to ENSTAR is. They will tell them what the cost of the gas is that Glenfarne is selling it to them for, and then determine how much ENSTAR can add to that to cover ENSTAR's cost. That's where the RCA would come in. I can confirm that, and we can certainly invite an RCA commissioner to join us at the table, but that's my understanding. 10:19:12 AM SENATOR KAWASAKI Just because we're talking about RCA and then who would figure this out, and I don't know who can answer this, but is the spur line from wherever to Fairbanks going to be rate regulated through RCA, or is it just a FERC project. If it's not with this AKLG, but it's a spur, who regulates that. 10:19:48 AM MR. KISSINGER It is my understanding that would be, that you mentioned, an in- state gas pipeline, and so therefore would fall under the Alaska state statutes. SENATOR KAWASAKI Maybe we will clarify with RCA at some point. CHAIR GIESSEL We absolutely will and I have that understanding also, that the RCA will regulate that gas pipeline. 10:20:16 AM SENATOR WIELECHOWSKI Just a hypothetical, and correct me if I'm wrong, but could we pass this bill with the assumptions that were given, and then it turns out, well, gas isn't really $1.50, it's $3, and the CapEx, the cost isn't really $46 billion, it's really $90 billion, and the rate of return isn't really 10 percent, it's 13 or 14 percent. Is that theoretically possible that could happen. The way the bill's currently written. 10:20:58 AM MR. KISSINGER This is difficult for me to apply in so many hypotheticals, so I apologize. SENATOR WIELECHOWSKI I'll break it down for you, Mr. Kissinger, if that's okay. Is it possible that the gas instead of being $1.50 could be $3. Is that possible. Yes or no. MR. KISSINGER It's theoretically possible, but I'm finding it difficult that we would be able to clear the market on the LNG side. So, hypothetically, yes, reasonably, no. 10:21:34 AM SENATOR WIELECHOWSKI Is it possible that the capex could be instead of $46 billion, $80 or $90 billion, yes or no. MR. KISSINGER If we're dealing in pure hypotheticals, any number, it could result in almost any number. I think it would be very difficult to clear the LNG market if capex estimated $90 billion and you also have cost overrun. We are now sitting on a class 2 cost estimate, which has a 15 percent accuracy rate band on it on the mainline pipeline, and we're moving into feed on the gas treatment plant and the LNG facility. Once feeders complete on those, we'll be able to apply with more confidence on the narrower band of what the capex should result in. I wouldn't expect that to be $90 billion. 10:22:30 AM SENATOR WIELECHOWSKI When can we expect that. MR. KISSINGER The developer is attempting to enter into feed the middle part of this year on both the gas treatment plant and the LNG facility, and that feed could take as long as one year to complete. 10:22:54 AM SENATOR WIELECHOWSKI When we heard earlier this year that pipe would start to be laid in December, is that being pushed back now. MR. KISSINGER It's important to differentiate between the pipeline and the GTP and LNG subprojects. The pipeline subproject, as I said, has a Class 2 cost estimate already on the mainline, and so, no, we're willing to move forward on phase one with that Class 2 cost estimate on the mainline pipeline. 10:23:28 AM SENATOR WIELECHOWSKI The pipe will still start to be laid in December of this year. MR. KISSINGER As I've mentioned before, I don't like to deal in setting hard timelines for achieving an FID. I'd rather talk about the ingredients going into the FID and how those ingredients are progressing over time. We've seen the gas sales, precedent agreements with the upstream, those need to be converted into definitive gas sales agreements. That's happening right now. We have the downstream gas sales agreement to ENSTAR and industrial customers. Those negotiations are ongoing. And ultimately, that will go into an RCA process. The RCA process will take a certain amount of time. That is less managed both on our side, and that all has to be factored in. Ideally, yes, by the end of the year, we would be laying pipe. 10:24:29 AM SENATOR MYERS You answered about half my questions already. Appreciate that. To clarify, going back to kind of consumer protection, my understanding of the process and of what you just said was that before FID, you guys and Glenfarne, are going to have to sign firm or binding contracts with Chugach and E and maybe a couple other customers in the south central that I'm forgetting in order to go to FID on phase one. But then before those contracts can get signed, ENSTAR has to have them approved by the RCA, meaning that it would be extremely difficult for ENSTAR, for Glenfarne to pass the cost on to the consumer if there's any significant cost overruns, because that would require ENSTAR or Chugach or somebody to turn around and go back to the RCA and get those contracts re-approved and renegotiated. Is that correct. 10:25:46 AM MR. KISSINGER I think that you've captured it exactly how I understand it. If I just can sort of repeat what you said for clarity, we would first enter into the gas purchase agreement and the gas sales agreement that underpin the financing on this project. We would then get the RCA approvals, we would get the financing, and if the project did have extreme cost overruns, it would not be a simple matter of turning around and just passing that cost on to the consumer, because the consumer, A, has a long-term contract in place, and B, that long-term contract requires the approval of the RCA. 10:26:35 AM SENATOR RAUSCHER I think the options are still out there. The whole idea behind this pipeline is to beat the cost of overseas, which I think is still an option if the price gets too high. I don't know if that's fact, but I think that that's also an option. And then there's always whatever we have in the inlet, whatever's left of whatever we have in the inlet. I think those, they compete against each other, so I assume that they have to take those into consideration too. That's just my opinion. 10:27:21 AM CHAIR GIESSEL I do want to interject here that Nick Fulford with Gaffney, Cline is online, and he sends a comment that he has slides on many of these questions and would be happy to jump in. I'm hesitant to do that because we do have Mr. Stickel at the table, and we still have more slides, so we will look forward to hearing from Mr. Fulford at our next hearing. 10:28:15 AM MR. STICKEL moved to slide 34, Sensitivity Matrix; LNG Break- Even Price, Nominal $/Mcf in 2033. Slide 34 is similar to what we had on slide 33, but looking at those LNG breakeven prices. What would the price have to be into the market under different gas purchase prices and capital costs. This bill would reduce the breakeven gas price for the developer from $9.07 down to $8.48 per thousand cubic feet under our baseline assumptions. My understanding is Gaffney, Cline has some excellent charts that kind of put those values into context in terms of current and historical market prices globally. 10:29:12 AM SENATOR DUNBAR This is going to Gaffney, Cline, but what is the current, price maybe is a little bit not the best use because of what's going on in Qatar and elsewhere, but what is the current price that we would be competing with, and what's the projected price in 2033 we would be competing with. MR. STICKEL I would defer some of those questions around exactly what we're competing against. I looked at futures market prices yesterday for delivered LNG into Asia. Currently, the prices are well over $10 per thousand cubic feet, especially over the very near term. There's a bit of a supply crunch. Once you go out into that early 2030s timeframe, the prices are lower. They're in the around $8 to $9 per thousand cubic feet range and really highlights that these delivered prices are right on the margin of being competitive. 10:30:22 AM SENATOR DUNBAR This is more to Mr. Kissinger. I'd like you to provide a little more detail about that. Let's say it's $10, we said, and it goes down because there are a bunch of other LNG projects that are coming online all over the world, including two potentially from Glenfarne. My two questions are, what are you assuming to be the price you're going to be competing with. Then second, I'm still struggling with this idea that the previous slide, that Alaskans will really get that price when we're only 5 percent of the volume that's coming down the pipe. Is there a world in which, let's say the South Central consumer in Alaska is getting gas out of this pipe that is more expensive than what we potentially could be importing from the LNG market. 10:31:42 AM MR. KISSINGER On a full build-out of the three train exports, I'd say no, that's not possible. We did have, in the Alaska Advantage principles, we have this concept of differential rates. So differential rates are where you can sell at a lower cost into one customer than another. For example, to bring on, we've talked about the Agrium plant. I think everyone would love to see the Agrium nitrogen plant back online. To do that, under phase one, if in-state customers are paying in the $13 range, you would not be able to bring that plant on. You use a tool called differential rates, and you go, what rate can you pay there. For hypothetical purposes, let's say that's $6. If they're paying $6, that would bring your in-state costs down from the $12, $13 range to the $10 range. In that instance, and apologies, but the same could be done with a single train of LNG. If you build with just the first train of LNG, you could take it off that way. Hypothetically, in that situation, you could have overseas customers paying less for the gas than the in-state customers. The way those differential rates are allowed under this Alaska Advantage principles is only where they achieve the one resting possible rate for in-state utility customers. It has to be demonstrated that we're benefiting from those differential rates. Even though it's a very hard pill to swallow, we still need to be demonstrating that we're at least benefiting from those differential rates and bringing down the cost to in-state customers from where they would otherwise be. 10:33:47 AM SENATOR DUNBAR I assume that exists in law, that principle, and you as a state agency, I assume, would be answering to the rest of state government on that. If that's not correct, let me know. Second, you know, our Department of Revenue has made some, different break-even prices. Where is ENSTAR assuming that the price will be in 2033. 10:34:24 AM MR. KISSINGER The way you look at the market is on the basis of a marginal supplier. You don't look at who can supply for the cheapest price into the market, which in a lot of different ways before the war was caught up. They don't sell at that low price if they produce that. Of course they sell at the market rate. The market rate gets set by whoever is producing into the market at the highest cost. That happens to be the U.S. Gulf Coast, generally. If you break down just the structure to go from Henry Hub pricing to delivered LNG into Asia, it goes something like this. You buy your gas at Henry Hub prices plus 15 percent. That 15 percent covers the fuel, the same way we had these questions earlier around why the costs are different. You still have to pay for your fuel in that low 48 model. If you're thinking of around a $4, maybe $4 plus, just to make the math easier, Henry Hub price, which is a decent forecast for long-term Henry Hub, you'd be around $5 by the time it's going into the LNG plant, because you're including that fuel. Liquefaction across the U.S. Gulf Coast is pretty standard. It's about $2.50 per MMBtu. So that puts you at $7.50 over there in the U.S. Gulf Coast, still needing to be delivered to Asia. It's about $2.50 to deliver from the U.S. Gulf Coast to Asia, a lot of that driven by the impacts of the Panama Canal or having to go the long way to get there because you avoid the Panama Canal. That achieves a delivered price into Asia of $10. Then you have to stress that. You have to be able to withstand periods of time when Henry Hub goes down to $2.50 like it does now. You also have to take into account that a lot of LNG is also priced on Brent. That's the math on U.S. Gulf Coast, moving to the math on Brent and it's usually sold as a percent of Brent. Through casual reading, I think you'd be able to discover that the price band is fairly narrow. It's somewhere around 12 percent, 13 percent, sometimes 14 percent, sometimes less, sometimes 11 percent Brent. Let's use 12 percent Brent as our assumption now. Where you're at $100 oil, you're paying $12 for the LNG. That's how that works. If you think of $75 oil, which is, a long-term stable view of oil, that would be $9 for an MMBtu. What we're trying to beat is somewhere in that $9 to $10 range. 10:37:13 AM SENATOR DUNBAR I think that's a good summary. It does illustrate perhaps the necessity of this legislation, but it also sort of illustrates that, as Mr. Stickel just said, this is in some ways a marginal project, and if you go over 20 percent cost overrun, you're not really competitive, even at $1.50, and certainly not at $2 or $2.50. It's good testimony for this bill. It sort of reiterates what I think a lot of us have been feeling, which is we are still skeptical that the private market will step in and invest in this project. 10:38:08 AM MR. STICKEL moved to slide 35, Sensitivity Matrix; Cumulative State Revenues through 2062, Nominal $ millions. This shows total cumulative state revenue over the life of the project. Under current law, state and municipal revenues would increase substantially with higher project costs. We assumed that those higher project costs would feed through to higher property tax valuations. You see some upside to state revenues under current law. Then the flip side of that is risk to higher state taxes for the developer. Under this proposal, state and municipal revenues would be lower across the board, but then they would not increase if there were higher project costs. When folks are saying that the bill de-risks the project, that's what they're talking about, both the lower tax burden overall and then lower risk of facing higher taxes if the project value comes in higher than expected. You see a similar sort of chart if we did this for municipal revenues, but even bigger numbers, since the majority of the property tax is to the municipal owners. 10:39:38 AM MR. STICKEL moved to slide 36, Sensitivity Scenarios; In-State Gas Cost, 2033 Nominal $/Mcf in 2033. Slide 36 is a tornado chart, another form of sensitivity analysis. What we did here is we looked at how certain key assumptions could impact that break-even in-state gas price. Under current law, starting with the $4.86 as our baseline price for delivered in-state gas, and we looked at property taxes, capital expenditures, that rate of return to the midstream, the purchase price of gas, and the interest rate paid on debt, and what higher or lower values for each of those would do to that break-even cost of supply. The biggest ways to reduce that required price for in-state gas would be through property tax relief and paying lower prices to the producers for the gas. The biggest risks to the upside would be higher than expected project costs and paying a higher value for the gas to the producers. You see this bill would de-risk that capital expenditures risk quite a bit in addition to reducing the property tax burden. 10:41:13 AM MR. STICKEL moved to slide 37, Sensitivity Scenarios; LNG export price, Nominal $/Mcf in 2033. by looking at the breakeven LNG export price, $9.07 per thousand cubic feet being the current law baseline, and we see the impact of those key assumptions on that required cost of supply. Lots of risk to the upside in this project, and you can see from looking at the capex number in particular, why it's important to the developer to de-risk that capex, especially if they think there's a chance that project costs could come in higher than the $46 billion that we've assumed. 10:41:59 AM CHAIR GIESSEL I'm looking at the cost of debt. I understand that there is some hope that the federal government will have some loan opportunities, and would that be at the lower interest rate. Where would that fall. 10:42:19 AM MR. STICKEL We assume a 5 percent interest rate for that cost of debt. If there was some sort of reduction to that, we show the impact if those rates were brought down to 3.5 percent, that would materially impact the breakeven prices, and then we show the impact of a higher cost of debt as well. The 5 percent is a baseline assumption. It incorporates the known information around the federal loan guarantees that do exist. Obviously, if there was additional support that would be enacted, that would be a positive to the project. 10:43:00 AM SENATOR CLAMAN Could you repeat the baseline price for the LNG export chart, this one. 10:43:06 AM MR. STICKEL $9.07 per thousand cubic feet in 2033 is our current law baseline. That's where we start this tornado chart. 10:43:26 AM MR. STICKEL moved to slide 38, Summary: Total Government Revenue, Part 1 of 2. Slide 38 shows a summary of total government revenues under this bill, and we show this over 10, 20, and 30 years of full production from the project. This is a snapshot of a detailed summary document that we've provided as a committee document, and we've split that into two slides here to make it reasonable. 10:43:59 AM SENATOR WIELECHOWSKI Looking at the upstream corporate income tax, what would that number be if all the producers on the North slope were paying a corporate income tax. 10:44:09 AM MR. STICKEL It would be about 50 percent higher, roughly speaking, about two-thirds of the producers are paying corporate income tax. 10:44:22 AM SENATOR WIELECHOWSKI What would that number for project corporate income tax look like if the pipeline developer or all the others involved in this project were paying a corporate income tax. 10:44:38 AM MR. STICKEL We can provide that. We haven't calculated that out here. We are assuming, conservatively, that the midstream would pay zero corporate income tax. 10:45:07 AM MR. STICKEL moved to slide 39, Summary: Total Government Revenue, Part 2 of 2. Slide 39 is the second half of this chart. This entire analysis has been provided as a committee document, but through the 30- year modeling period, looking at a total of $22.5 billion of state benefits over the life of project, and then nearly $4 billion to the municipalities over the life of project, and federal government income tax benefits netting about $22 billion over life of project, so a total of $48 billion to the various governments through 2062. 10:45:47 AM SENATOR MYERS If you're going to provide us numbers about if the midstream was paying the corporate income tax, could you also provide an estimate of what that would do to the gas cost, both for in- state and for LNG sales. 10:46:05 AM MR. STICKEL Yes. 10:46:10 AM SENATOR WIELECHOWSKI Looking at the oil production tax, why is that a decrease of a couple hundred million dollars from 2052 to 2062. 10:46:21 AM MR. STICKEL These are positive impacts above and beyond the revenue forecast, and what our modeling does is it accounts for all of the impacts of the ability of companies to deduct lease expenditures against the oil tax. It accounts for all of the impacts of per-taxable barrel credits, and going from the 2052 to the 2062 timeframe, we see a net increase in the production tax paid to the state overall when you combine the oil and the gas pieces, but some of the lease expenditure deductions and per-taxable barrel credits do reduce the oil side of things. In our modeling, we calculate out the gas production tax, the 13 percent gross tax, we calculate out the oil tax net of everything, and then we add them together to get the total production tax impact. 10:47:33 AM SENATOR WIELECHOWSKI Am I reading that correctly, that the oil production tax is $1.6 billion positive through 2052, but then it declines by $275 million through the next 10 years. 10:47:50 AM MR. STICKEL Yeah, from the 2053 to 2062 timeframe, we do expect a reduction in oil production tax relative to the forecast, but that will be more than offset by increase to gas production tax. 10:48:18 AM CHAIR GIESSEL Is this reflecting the deductions they can take against their oil taxes as they produce more gas. 10:48:29 AM MR. STICKEL All our modeling accounts for the fact that under our current production tax law, any incremental lease expenditures associated with gas development can be deducted against the oil tax calculation. We also account for the nuances of the per- taxable barrel credits, which those are generated based on oil production and applied based on the statewide tax calculation. Both of those factors are built into our modeling. 10:49:07 AM MR. STICKEL moved to slide 40, Conclusions. The AK LNG project, if it was constructed, it would provide billions of dollars to the state and the federal government and local governments. It would provide a new revenue stream to the upstream producers and a new revenue stream for a midstream developer. It would provide jobs and support energy security in the state and nationally. This bill would reduce the tax burden on the developer, making the project relatively more economic and would help de-risk the project in terms of reducing the potential impacts of higher project costs or higher tax assessments. 10:50:02 AM CHAIR GIESSEL The next few slides are sectionals, which we don't have to go through. I do want to ask you a question, however, on slide 46, and this relates to Alaska statute 4356-022. This is where it imposes a replacement of all state and municipal property ad valorem, et cetera, taxes. It's all written there. Looking at this, it's unclear to me whether this is confined to certain oil and gas properties or if this applies across the state. Would it be applying then to qualified property under that definition that is in Cook Inlet, for example, or in Middle Earth. 10:50:55 AM MR. STICKEL I can speak to what my understanding of the intent is. The intent is, if you look at current property tax law, there's language in the statutes that property tax is in lieu of other similar taxes. That's kind of the intent is a fairly narrow exclusion. Municipalities, the volumetric tax would be in lieu of the property tax or similar taxes. And so the intent of that is not to provide an extremely broad exclusion, but a narrow exclusion. We've got Department of Law on who can opine on in further detail if that's helpful. 10:51:40 AM CHAIR GIESSEL It would be. Let's see. Ryan Farnsworth is online with the Department of Law. Mr. Farnsworth, how broadly can this exclusion be applied. 10:51:56 AM RYAN FARNSWORTH, Assistant Attorney General, Department of Law, Anchorage, Alaska, answered questions on SB 280. Is the question about the abatement of property tax. CHAIR GIESSEL Yes, its on slide 46, but its section 4356-022. It seems very broad. It pertains to purchase, use, consumption, or ownership of property or services in that municipality or jurisdiction. 10:52:33 AM MR. FARNSWORTH It is a broad exemption. CHAIR GIESSEL Could it be applied to, let's say, the Glenfarne, or AGDC has an employee that lives in Bethel, and they come to work for two weeks in Kenai. They're building the export facility. They are going to go to buy some groceries. We're talking now about consumption, right. Purchase, use, consumption. Can they be waived. Can they receive a waiver on the property or the municipal sales tax when they go back to Bethel as well, or only in the Kenai Borough, or how will that apply to the employee. 10:53:33 AM MR. FARNSWORTH I don't think the employee would be exempted from sales tax for lunch purchased while working. It would have to be property that's definitely something contributed to the project by contract, so perhaps catering for a large event, something like that for the project, but I don't think individual lunches would be exempt. 10:53:56 AM CHAIR GIESSEL That is not defined here. You're making an assumption because, of course, regulations haven't been written to apply this. Is that true. 10:54:09 AM MR. FARNSWORTH No, because the alternative, the exemption from the tax is related to the qualified property, so it has to be related to the property, the project, or something associated. 10:54:26 AM SENATOR DUNBAR I just want to ask another hypothetical, just a little bit more direct. If Glenfarne brought in a bunch of contractors that, again, were working directly on the project, and they stayed in Anchorage for a week in hotels, would they be exempt from our bed tax. 10:54:46 AM MR. FARNSWORTH I would say no to that. 10:54:50 AM SENATOR DUNBAR Why. The way it's written here. I don't understand why having construction or contract employees that are directly working on the project wouldn't be associated with the project. Are you saying it has to be something physical, physically attached to the project. MR. FARNSWORTH Not necessarily. It depends who's paying that bill, if the project's being billed or the individual. 10:55:36 AM SENATOR DUNBAR What about Anchorage gas tax if you're filling up a bunch of trucks headed to the project carrying things for the project. Are they exempt from Anchorage gas tax. MR. FARNSWORTH That's probably a little detail that isn't in this statute, this draft. 10:56:09 AM SENATOR WIELECHOWSKI I'm curious if the Department of Revenue included in their modeling how much this section would cost the municipalities or the state. 10:56:22 AM MR. STICKEL We modeled to what I understand is the intent of the section. I understand that there may be an amendment to tighten up the language here that would be helpful. I did have discussions with the Governor's office to understand what was intended here. The intent is a narrow exemption, basically to disallow a property tax by another name. That's what the ABT would be a replacement for the property tax and the type of property that would be taxable under a property tax. The intent is not to include bed taxes and sales taxes and things like that. When we did our modeling, we modeled to that intent. We looked at the reduction to the property tax and then the imposition of the alternative volumetric tax. 10:57:21 AM SENATOR WIELECHOWSKI Different topic, but just a request. 10:57:26 AM CHAIR GIESSEL Could I follow up then just briefly on that. You're saying that's the intent, but would you agree that that intent is not actually fleshed out in this statement of a statute. 10:57:37 AM MR. STICKEL We would need to put regulations into place. I would suggest that we would look at that intent when crafting those regulations. If we wanted to put the additional clarity into statute, that could be certainly helpful. 10:57:54 AM SENATOR WIELECHOWSKI A request for the department if they could get us. Slide 33 was the sensitivity matrix for in-state gas as of 2033. That's phase two. I'd like to see that chart for phase one. I think that'd be beneficial to the to the committee. Do you understand that. 10:58:17 AM MR. STICKEL This would be a phase one only if the full project did not proceed. We are in the process of preparing that modeling. When it's ready, we will re-present that. 10:58:29 AM SENATOR WIELECHOWSKI Then I had a question for Mr. Kissinger. I've heard from constituents and other legislators that there are ads running just on the radio and on political blogs urging support for the LNG projects. I'm just curious who's paying for those. 10:58:52 AM MR. KISSINGER It's my understanding that Glenfarne is paying for those. 10:59:03 AM SENATOR WIELECHOWSKI Is AEDC paying for those in any way, or have you approved of those. 10:59:13 AM MR. KISSINGER We have neither approved them nor paid for them. 10:59:23 AM SENATOR CLAMAN I want to go back to the discussion about regulations, Mr. Stickel. There's this theme that we often hear, the regulations have to comply with the law and the regulations can't do more than the law, and if we have regulations that do one thing and the law doesn't go that far, then there's a lawsuit and says, well, those regulations are improper. If we're concerned that this, as drafted, is too broad, why would we rely on regulations to straighten it out. 10:59:58 AM MR. STICKEL I'm an economist, not a lawyer. If I were involved in the regulation process, I shared what my view would be and what the intent and direction from the administration was in this. Certainly, we'd be happy to look at potential amendments to strengthen up that language to make sure that it does indeed match what the intent is. 11:01:01 AM [CHAIR GIESSEL held SB 280 in committee.] 11:01:12 AM There being no further business to come before the committee, Chair Giessel adjourned the Senate Resources Standing Committee meeting at 11:01 a.m.